Zaluski, Wade (Schlumberger Canada LTD) | Andjelkovic, Dragan (Schlumberger Canada LTD) | Xu, Cindy (Schlumberger Canada LTD) | Rivero, Jose A. (Schlumberger Canada LTD) | Faskhoodi, Majid (Schlumberger Canada LTD) | Ali Lahmar, Hakima (Schlumberger Canada LTD) | Mukisa, Herman (Schlumberger Canada LTD) | Kadir, Hanatu (Schlumberger Canada Limited now with ExxonMobil) | Ibelegbu, Charles (Schlumberger Canada Limited) | Pearson, Warren (Pulse Oil Operating Corp) | Ameuri, Raouf (Schlumberger Canada Limited) | Sawchuk, William (Pulse Oil Operating Corp)
Enhanced oil recovery (EOR) is an economic way of producing the remaining oil out of previously produced Devonian Pinnacle Reefs in the Nisku Formation within the Bigoray area of Alberta. To maximize the recovery factor of the remaining oil, it was necessary to first characterize the geological structure, matrix reservoir properties, vugular porosity and the natural fracture network of these two carbonate reefs. This characterization model was then used for reservoir simulation history matching and production forecasting further discussed by (
Yu, Hao (Southwest Petroleum University, China) | Dahi Taleghani, Arash (Pennsylvania State University, United States) | Lian, Zhanghua (Southwest Petroleum University, China) | Lin, Tiejun (Southwest Petroleum University, China)
Microseismic data and production logs in our study area have confirmed an asymmetric development of the stimulation rock volume, while severe casing deformation problems have been reported frequently in this area. In this paper, we investigate the possibility of casing failure due to strong shear stresses developed by asymmetric stimulated zones. Overlapping stimulation zones in adjacent stages may intensify asymmetry of the pore pressure distribution and resultant shear forces. Although induced shearing may have a positive impact on fracture permeability, but it may also cause operational problems by inducing severe casing deformations. While most of the casing deformation models only consider rock deformations very close to the wellbore, we developed a 3D coupled model for fracture network growth and stress re-distribution during hydraulic fracturing to achieve a more realistic model for casing deformation. This reservoir-scale model is tied to a more detailed near-wellbore model including the casing and cement sheath to simulate casing deformations. Case studies were conducted using data from a shale gas well that experienced severe casing deformation during hydraulic fracturing. Impact of stage spacing, and pumping rate are incorporated to investigate their potential impacts on casing and well integrity. Multi-stage hydraulic fracturing considering the development of complex fracture network is simulated at the reservoir scale based on the microseismic events. Continuous re-distribution and re-orientation of stress field near the borehole are tracked during the development of the fracture network which reveals some pocket of tensile stresses along the casing. Asymmetric fractures are observed to generate strong shear stress on the suspended casing. These shear forces result in deflection and S-shape deformations. Some regions receive repeating treatments, which leads to increase formation stress heterogeneity and worsen casing deformation severity. Our analysis has indicated that simply increasing the flexural strength by increasing thickness of casing cannot radically mitigate casing deformation problems. This paper provides a novel workflow for a coupled modelling of casing deformation during hydraulic fracturing operations, while current modelling efforts assume symmetric fracture geometries.
Ugueto, Gustavo A. (Shell Exploration and Production) | Todea, Felix (Shell Canada Limited) | Daredia, Talib (Shell Canada Limited) | Wojtaszek, Magdalena (Shell Global Solutions International) | Huckabee, Paul T. (Shell Exploration and Production) | Reynolds, Alan (Shell Exploration and Production) | Laing, Carson (OptaSense) | Chavarria, J. Andres (OptaSense)
The use of Distributed Acoustic Sensing for Strain Fronts (DAS-SF) is gaining popularity as one of the tools to help characterize the geometries of hydraulic fracs and to assess the far-field efficiencies of stimulation operations in Unconventional Reservoirs. These strain fronts are caused by deformation of the rock during hydraulic fracture stimulation (HFS) which produces a characteristic strain signature measurable by interrogating a glass fiber in wells instrumented with a fiber optic (FO) cable cemented behind casing. This DAS application was first developed by Shell and OptaSense from datasets acquired in the Groundbirch Montney in Canada. In this paper we show examples of DAS-SF in wells stimulated for a variety of completion systems: plug-and-perforating (PnP), open hole packer sleeves (OHPS), as well as, data from a well completed via both ball-activated cemented single point entry sleeves (Ba-cSPES) and coil-tubing activated cemented single point entry sleeves (CTa-cSPES). By measuring the strain fronts during stimulation from nearby offset wells, it was observed that most stimulated stages produced far-field strain gradient responses in the monitor well. When mapped in space, the strain responses were found to agree with and confirm the dominant planar fracture geometry proposed for the Montney, with hydraulic fractures propagating in a direction perpendicular to the minimum stress. However; several unexpected and inconsistent off-azimuth events were also observed during the offset well stimulations in which the strain fronts were detected at locations already stimulated by previous stages. Through further integration and the analysis of multiple data sources, it was discovered that these strain events corresponded with stage isolation defects in the stimulated well, leading to "re-stimulation" of prior fracs and inefficient resource development. The strain front monitoring in the Montney has provided greater confidence in the planar fracture geometry hypothesis for this formation. The high resolution frac geometry information provided by DAS-SF away from the wellbore in the far-field has also enabled us to improve stage offsetting and well azimuth strategies. In addition, identifying the re-stimulation and loss of resource access that occurs with poor stage isolation also shows opportunities for improvement in future completion programs. This in turn, should allow us to optimize operational decisions to more effectively access the intended resource volumes. These datasets show how monitoring high-resolution deformation via FO combined with the integration of other data can provide high confidence insights about stimulation efficiency, frac geometry and well construction defects not available via other means.
This course will present the workflows that have been developed along with spreadsheet-based exercises to solidify concepts. The workshop provides in-depth presentations and discussions of the models presented. This course examines datasets from both conventional and unconventional systems and present workflows to construct naturally-fractured reservoir models. Particular attention will be given to the use and calibration of a variety of 3D seismic attributes, which are critical to our characterization efforts. The combination of 3D seismic data with sound stratigraphic and structural frameworks provides a more robust fractured reservoir model.
The development and management of naturally fractured reservoirs (NFRs) is a challenging task for asset teams due to the complexity of these reservoirs. The challenges are observed from the initial exploration phase and continue up to the field development stage. Placing production and injection wells in NFRs pose serious challenges. In most cases, highly permeable fractures are encountered during drilling leading to substantial loss of drilling fluids and extensive use of loss circulation materials. Thus, asset teams need to proactively predict location of these highly conductive fractures since they act as channels for rapid water or gas movement leading to early breakthrough and poor volumetric sweep efficiency.
Bessa, Fadila (Occidental Petroleum Corporation) | Sahni, Vinay (Occidental Petroleum Corporation) | Liu, Shunhua (Occidental Petroleum Corporation) | Tan, Jiasen (Occidental Petroleum Corporation) | Frass, Manfred (Occidental Petroleum Corporation) | Kessler, James (Occidental Petroleum Corporation)
Understanding and modeling the interaction between hydraulic fractures and natural fractures is important to predict shale production performance. This paper presents a workflow that incorporates natural fractures, rock properties, and stress regimes to understand fracture behavior during stimulation treatment. The methodology also integrates the predefined discrete fracture network (DFN) and 3D reservoir properties to build a comprehensive hydraulic fracturing model. Heat maps are also generated to help evaluate completion design and well spacing strategies.
Applying the integrated fracture characterization workflow to the study area revealed that the vertical and lateral fracture growth is a function of structural context, stress conditions, and rock mechanical properties. Stimulation parameters, including proppant volume and injection pressures, for one horizontal and six vertical wells were utilized to build a comprehensive fracture network for the study area. The resulting model shows: (a) the stimulation of predefined natural fractures, and (b) the generation of induced fractures in the maximum stress direction associated with re-activation of pre-existing faults and fractures. The modeling results were validated by interwell interference data.
Fractures play an important role in hydrocarbon production from organic-rich shale reservoirs (Gale, et al., 2014). This is evident from the higher than expected production rates typically observed from low-porosity and ultra-low permeability shale rocks. Moreover, many shale outcrops, cores, and image logs show an abundance of natural fractures or fracture traces. This study integrates natural fracture characteristics, directional stresses, and hydraulic fractures to characterize and better comprehend Permian Wolfcamp production performance.
Several factors influence the stimulated rock volume (SRV) geometry during a hydraulic fracturing stimulation treatment. These factors include: structural context, natural fracture networks, rock mechanical properties, lithology, and stress changes associated with tectonic events (Gale et al., 2014; Maity, 2018). Furthermore, natural fracture systems in shales are heterogeneous; they can enhance or reduce formation productivity, augment or diminish rock strength, and may have a tendency to influence hydraulic fracture stimulation (Doe et al., 2013). The flow of stimulation fluid through natural fractures and the generation of hydraulic fractures were modeled in this study.
Objectives and Scope: Natural fractures were observed in core and image logs from the Hydraulic Fracture Test Site (HFTS) in Reagan Co., Texas. This paper provides an analysis of these fractures, including their orientation, size, spatial distribution, and openness.
Methods: We measured kinematic aperture sizes of two sets of sealed, opening-mode natural fractures in a slant core taken through a stimulated volume, and we analyzed the population distribution using cumulative frequency plots. For the spatial organization study, in addition to fractures identified in the slant core, we used data from image logs from three nearby horizontal producing wells. The spatial organization of fractures was investigated using our statistical method, Normalized Correlation Count (NCC), and by calculating the Coefficient of Variation, Cv, which is a measure of clustering.
Results: In the slant core 197 Set 1 (NE-SW) fractures are present (154 kinematic apertures measured), and there are 112 Set 2 (WNW-ESE) fractures (62 measured). The aperture-size distribution for Set 1 fractures follows a negative-exponential function, whereas Set 2 fractures follow a weak power-law. Only two fractures, both in Set 1 and ~ 1 mm wide, were open in the subsurface, although many more are now parted, mostly in Set 2. Linear intensity, P10, for measured fractures ≥1 mm wide is 0.01 frac/ft (Set 1) and 0.006 frac/ft (Set 2). Both natural fracture sets in an FMI image log from a nearby well have spatial arrangement patterns of regularly-spaced fractal clusters and Cv greater than 3 (3.22 to 4.05). Fracture cluster widths are 100–200 m, and cluster spacings range from 350–600 m. Fractures in COI image logs in two other wells have lower Cv (1.59 to 2.32). Both sets in the 6U well and Set 1 in the 6M well show elevated intensity along the middle section of the well and NCC indicates broad, but weak non-fractal clustering, likely related to lithological control of fracture growth. In the slant core Upper Wolfcamp Set 1 fractures are indistinguishable from random; Set 2 show a log-periodic clustering but with Cv less than 2.
Significance: Incorporation of Discrete Fracture Networks (DFN's) into hydraulic fracture modeling and reservoir simulation requires high-quality natural fracture data from image logs and core. This paper provides such data and provides information on natural-hydraulic fracture interaction at the HFTS site.
Growth in a number of newly drilled wells in unconventional reservoir development results in tightly spaced horizontal wells, which consequently creates well interference (fracture hits) between parent and infill wells as a result of stress redistribution from localized pressure sink zone in parent wells. This directly affects the production performance of both parent and infill wells. In order to minimize this effect, it is sometimes more preferable to place an infill well in a different pay zone. However; due to poroelastic effect, pressure depletion from the parent well also affects stress distribution in different pay zones and yet only a few literatures focus on this effect. The main objective of this paper is to predict temporal and spatial evolution of stress field for Permian basin using an in-house 3D reservoir-geomechanics model and propose guidelines for determining lateral and vertical drilling sequence of infill wells to mitigate well interference.
Embedded discrete fracture model (EDFM) is coupled with a sequentially coupled reservoir-geomechanics model to gain capability in simulating complex fracture geometries and high-density fracture system. Different scenarios with and without natural fractures were studied including a case where two parent wells are located in different layers (Wolfcamp A2 and B2) and a case where two parents are located in the same layer (Wolfcamp A2 and B2). Stress redistribution is then observed to determine the completion sequence of infill wells in different layers.
Producing two parent wells in the same pay zone results in large stress redistribution mostly in the area close to fracture tips at an early time. As time progresses, stress redistribution area becomes larger and covers almost entire infill well zone in Wolfcamp B2. Stress changes can also be observed in Wolfcamp A2 and A3 despite producing wells are only located in Wolfcamp B2. However, when producing two parent wells in different pay zones, stress redistribution can only be observed near fracture tips in both Wolfcamp A2 and B2 with minimum stress change in the infill zone even at a later time in all Wolfcamps A2, A3, and B2. This allows the possibility of producing infill well in the un-depleted layers (i.e. A3) enhancing efficiency of infill well completion. Fracture penetration and larger fracture length also play a significant effect in stress reorientation and evolution. Presence of natural fractures causes stress reorientation to occur at an earlier time due to higher depletion rate. This paper presents the possibility of changing the sequence of stacked pay from lateral well layout to vertical well layout in order to mitigate well inference and improve production performance of both parent and infill wells. Less stress change in the infill zone for vertical well layout makes it become superior to lateral well layout in which large stress redistribution can be observed.
Applications, Significance, and Novelty: The proposed methodology may be widely applied, since it relies on available standard well and completion data. This method can be used on (i) legacy projects where offset pressure data was recorded; (ii) post job analysis of recent completions, and (iii) near real-time analysis of current completions.
Zhang, Hui (PetroChina) | Wang, Lizhi (Schlumberger) | Wang, Zhimin (PetroChina) | Pan, Yuanwei (Schlumberger) | Wang, Haiying (PetroChina) | Qiu, Kaibin (Schlumberger) | Liu, Xinyu (PetroChina) | Yang, Pin (Schlumberger)
Located at the foothills of Tianshan mountains, western China, the Dibei tight gas reservoir has become one of the key exploration areas in last decade because of its large gas reserve potential. The previous exploration effort yielded mixed results with large variations of the production rates from these exploration wells and many rates are too low to be deemed as discovery wells. Petrophysical properties were excluded as controlling factors because these properties for most exploration wells are very similar. Under the large tectonic stress, heterogeneous natural fracture systems are induced and unevenly distributed in the reservoir, which might be the controlling factor for production. However, due to the limitation of the seismic data quality, quantitative fracture modeling with seismic is not possible for this field. A new method predicting the 3D occurrence of the natural fractures in the reservoir is needed.
In this study, geomechanics-based methods were used to predict the natural fracture systems in the reservoir. The methods started from classification of natural fracture systems based on borehole image and core data into either fold-related and/or fault-related fractures. Geomechanics-based structure restoration was conducted to compute the deformation and the perturbed stress field from the restoration of complex geological structures through time. A correlation was established between the fold-related perturbated stress field and the occurrence of fold-related fractures from wells to predict the 3D occurrence of this type of natural fractures. Meanwhile, the computation of the perturbed stress field around 3D discontinuities (i.e. faults) for one or more tectonic events was conducted by the Boundary Element Method (BEM) until a good match was achieved between the fault-related perturbed stresses and observed fault-related fractures from the wellbore. By using the output from the two methods, the discrete fracture network (DFN) model was constructed to explicitly represent the occurrence and geometry of the natural fracture system in the reservoir in a geological model. A geomechanical model was constructed based on an integrated workflow from 1D to 3D. The fracture stability was then calculated based on the 3D geomechnical model.
Detailed analysis was conducted among the DFN model, the geological model of the reservoir and productivity of the exploration wells, and very good correlation was revealed between the productivity of the exploration wells and the occurrence and geometry of the natural fractures and the structural position of the reservoir.
This study shows that geomechanics-based methods efficiently capture the occurrence of natural fracture systems and reveal the production-controlling factors of the tight gas reservoir. It demonstrates that geomechanics is a powerful tool to support successful exploration of the tight gas reservoir in tectonically stressed environments.